The method and system disclosed herein, in general, relates to capturing carbon dioxide (CO2) from combustion sources such as flue gas of a power plant and making the CO2 available for sequestration or other uses.
Emissions of greenhouse gases such as carbon dioxide (CO2), if left unchecked, may potentially affect climatic conditions. Conversion of fossil fuels such as coal and natural gas to energy is a source of greenhouse gas emissions. Emissions of the greenhouse gases can be reduced by various means, for example, increase in efficiency of the combustion process and use of renewable energy such as wind energy and solar energy. However, the reduction in the emission of the greenhouse gases required to stabilize greenhouse gas levels cannot be achieved without capturing a substantial part of the greenhouse gases at the source of the greenhouse gas emissions during either a pre-combustion process or a post combustion process. Post combustion capture of CO2 from flue gas of a power plant or other streams such as flue gas from a refinery involves use of a solvent, typically an amine, which is regenerated using a part of a steam generated during the combustion process. Pre-combustion capture of CO2 involves a chemical reaction of a fuel with air or oxygen and then with steam to produce a mixture of CO2 and hydrogen. The CO2 is removed from this stream through a CO2 capture process and hydrogen may be used as a fuel for power generation. If oxygen is used for combustion, a flue gas containing mainly CO2 is produced which can be easily separated for sequestration.
The post combustion capture of CO2 results in, for example, about a 9%-11% reduction in absolute efficiency for power generation and about 28%-30% reduction in the relative efficiency for a pulverized coal power plant as discussed by Ciferno (Ciferno, J., “A Feasibility Study of Carbon Dioxide Capture from an Existing Coal-Fired Power Plant” paper presented at the Sixth Annual Conference on Carbon Capture and Sequestration, Pittsburgh, Pa., May 2007). A May 2007 National Energy Technology Laboratory (NETL) report, for example, Carbon Sequestration Technology Roadmap and Program Plan—2007, U.S. Department Of Energy (DOE) NETL, May 2007 shows about a 60%-100% increase in cost of power generation for existing power plants taking into account capital and operating costs for CO2 separation and sequestration. Net power output from the power plant is also decreased by 30% or more. Means to significantly decrease the power and capital penalty associated with the post combustion CO2 capture are sought. For the post combustion capture, the U.S. DOE has a goal of less than about a 35% increase in power cost for about 90% CO2 capture.
Most studies dealing with post combustion CO2 capture use amine or ammonia based absorption processes for removal of carbon dioxide (CO2) from flue gas. The absorption based processes have drawbacks such as significant capital and energy requirements. The best amine based absorbents such as the hindered amines and amine blends have an energy requirement in the range of, for example, about 750-900 Kcal/kg (1,350-1,620 Btu/lb) of the CO2 captured. Furthermore, amine based processes require the use of specialty steel equipment and associated capital investment because of the corrosive nature of amine and ammonia solutions in the presence of acidic gases and oxygen. This specialty steel equipment represents a significant capital cost.
Absorption systems that do not involve an aqueous amine have been proposed. These absorption systems include CO2 binding organic liquids such as those described by Heldebrandt et al. (Heldebrandt, D. J., C. R. Yonker, P. G. Jessop, and L. Phan, Organic Liquid CO2 Capture Agents with High Gravimetric CO2 Capacity, Energy Environ Sci, v1, p 487-493, 2008; and Heldebrandt, D. J., P. K. Koech, J. E. Rainbolt, F. Zheng, T. Smurthwaite, C. J. Freeman, M. Oss, and I. Leito, Performance of Single Component CO2 Binding Organic Liquids (CO2BOLs) for Post Combustion CO2 Capture, Chem Eng J., v171, p′794-800, 2011). The absorption systems also include physical and chemical ionic liquids as discussed in reviews by Zhang et al. (Zhang, X., X. Zhang, H. Dong, Z. Zhao, S. Zhang, and Y. Huang, Carbon Capture with Ionic Liquids: Overview and Progress, Energy Environ Sci, v5, p 6668, 2012.) and Ramdin et al. (Ramdin, M., T. W. de Loos, and T. J. H. Vlugt, State of the Art CO2 capture with Ionic Liquids, Ind Eng Chem Res, v51, p 8149, 2012.). In many cases, these solvents could perform better provided the amount of water and acid gases such as sulfur oxide (SOX) in the feed was significantly lower than that contained in a typical flue gas.
In contrast to the amine based systems, the heats of adsorption of CO2 on various zeolite and carbon based adsorbents range, for example, between 140-240 kcal/kg or 252-432 Btu/lb (Valenzuela, D. P. and A. L Myers, “Adsorption Equilibrium Data Handbook”, Prentice Hall, Englewood Cliffs, N.J., 1989), which is about a fifth of the total energy needed for the amine based systems. There is an unmet need for practical adsorption systems that can take advantage of low heats of adsorption while providing high carbon dioxide yield and high recovery.
Temperature swing adsorption systems have been used extensively for applications such as air drying, natural gas drying, and water and CO2 removal prior to cryogenic distillation of air. These temperature swing adsorption systems typically remove less than about 2% of impurities and the regeneration outlet stream containing the impurities is not of high purity. Also, the typical temperature swing adsorption processes have adsorption times of the order of about 4 hours to about 12 hours. For feed CO2 concentrations between about 10% to about 12% in the flue gas, these adsorption times would require extremely large adsorption beds. For example, assuming a working capacity of 12 weight % (difference in capacity between the adsorption and the regeneration steps), an adsorbent density of about 660 kgs/m3, and an adsorption time of 4 hours, a plant processing 1000 tons/day of CO2 in the feed would require about 8,000 m3, that is, 5.3 million kilograms of the adsorbent, a size that makes these systems not practical for capturing CO2 from combustion sources.
Vacuum swing adsorption (VSA) systems for CO2 recovery from flue gas have been proposed (Zhang, J., P. Xiao, G. Li, and P. A. Webley, Effect of Flue Gas Impurities on CO2 Capture Performance from Flue Gas at Coal Fired Power Stations by Vacuum Swing Adsorption, Energy Procedia, v1, p 1115, 2009; and Zhang, J., P. A. Webley, and P. Xiao, Effect of Process Parameters on Power Requirements of Vacuum Swing Adsorption Technology for CO2 Capture from Flue Gas, Energy Conversion and Management, v49, p 346, 2008). These vacuum swing adsorption systems typically have low adsorbent utilization leading to large systems, lower recovery and purities, and are impacted significantly by flue gas impurities such as water and SOX. These vacuum swing adsorption systems can benefit significantly from removal of water and acid gas impurities from flue gas prior to CO2 adsorption as impurities such as SOX are difficult to remove under vacuum swing adsorption operating conditions.
Hence, there is a long felt but unresolved need for an efficient capture of CO2 using a method based on temperature and pressure swing adsorption cycles either alone or in combination with other CO2 separation processes.